Wellbores are formed in subterranean formations for various purposes including, for example, extraction of oil and gas from subterranean formations and extraction of geothermal heat from subterranean formations. Wellbores may be formed in subterranean formations using earth-boring tools such as, for example, drill bits (e.g., rotary drill bits, percussion bits, coring bits, etc.) for drilling wellbores and reamers for enlarging the diameters of previously drilled wellbores. Different types of drill bits are known in the art including, for example, fixed-cutter bits (which are often referred to in the art as “drag” bits), rolling-cutter bits (which are often referred to in the art as “rock” bits), diamond-impregnated bits, and hybrid bits (which may include, for example, both fixed cutters and rolling cutters).
To drill a wellbore with a drill bit, the drill bit is rotated and advanced into the subterranean formation under an applied axial force, commonly known as “weight-on-bit.” As the drill bit rotates, the cutters or abrasive structures thereof cut, crush, shear, and/or abrade away the formation material to form the wellbore. A diameter of the wellbore drilled by the drill bit may be defined by the cutting structures disposed at the largest outer diameter of the drill bit.
The drill bit is coupled, either directly or indirectly, to an end of what is referred to in the art as a “drill string,” which comprises a series of elongated tubular segments connected end-to-end that extends into the wellbore from the surface of the formation. Often various subs and other components, such as a downhole motor, as well as the drill bit, may be coupled together at the distal end of the drill string at the bottom of the wellbore being drilled. This assembly of components is referred to in the art as a “bottom-hole assembly” (BHA).
The drill bit may be rotated within the wellbore by rotating the drill string from the surface of the formation, or the drill bit may be rotated by coupling the drill bit to a downhole motor, which is also coupled to the drill string and disposed proximate the bottom of the wellbore. The downhole motor may comprise, for example, a hydraulic Moineau-type motor having a shaft to which the drill bit is mounted, that may be caused to rotate by pumping fluid (e.g., drilling fluid or “mud”) from the surface of the formation down through the center of the drill string, through the hydraulic motor, out from nozzles in the drill bit, and back up to the surface of the formation through the annulus between the outer surface of the drill string and the exposed surface of the formation within the wellbore.
It is known in the art to use what are referred to in the art as “reamers” (also referred to in the art as “hole opening devices” or “hole openers”) in conjunction with a drill bit as part of a bottom-hole assembly when drilling a wellbore in a subterranean formation. In such a configuration, the drill bit operates as a “pilot” bit to form a pilot bore in the subterranean formation. As the drill bit and bottom-hole assembly advance into the formation, the reamer device follows the drill bit through the pilot bore and enlarges the diameter of, or “reams,” the pilot bore. Reamers may also be employed without drill bits to enlarge a previously drilled wellbore.
As noted above, when a wellbore is being drilled in a formation, axial force or “weight” is applied to the drill bit (and reamer device, if used) to cause the drill bit to advance into the formation as the drill bit drills the wellbore therein. This force or weight is referred to in the art as the “weight-on-bit” (WOB).
It is known in the art to employ what are referred to as “depth-of-cut control” (DOCC) features on earth-boring drill bits. For example, U.S. Pat. No. 6,298,930 to Sinor et al., issued Oct. 9, 2001 discloses rotary drag bits that include exterior features to control the depth of cut by cutters mounted thereon, so as to control the volume of formation material cut per bit rotation as well as the reactive torque experienced by the bit and an associated bottom-hole assembly. The exterior features may provide sufficient bearing area so as to support the drill bit against the bottom of the borehole under weight-on-bit without exceeding the compressive strength of the formation rock.